The oil and gas industry uses various methods to test the productivity of wells prior to completing and tying a well into a pipeline or battery. After drilling operations have been completed and a well has been drilled to total depth ("TD"), or prior to reaching TD in the case of multi-zoned discoveries, it is common to perform a drill stem test ("DST"). This test estimates future production of oil or gas and can justify a further expenditure of capital to complete the well.
The decision to "case" a well to a particular depth, known as a "casing point election", can result in an expenditure in excess of $300,000. Without a DST, a wellsite geologist must make a casing point election based on only core samples, cuttings, well logs, or other indicators of pay thicknesses. In many cases reservoir factors that were not knowable at the time of first penetration of the producing zone, and thus not reflected in the samples, cuttings, etc., can control the ultimate production of a well. A wellsite geologist's problem is exacerbated if the well is exploratory, or a wildcat well, without the benefit of comparative adjacent well information. Further, the geologist must make a casing point election quickly as rig time is charged by the hour.
A DST comprises, thus, a valuable and commonly used method for determining the productivity of a well so that optimal information is available to the geologist to make a casing point election. Traditionally the DST process involves flowing a well through a length of drill pipe reinserted through the static drilling fluid. The bottom of the pipe will attach to a tool or device with openings through which well fluids can enter. This perforated section is placed across an anticipated producing formation and sealed off from the rest of the wellbore with packers, frequently a pair of packers placed both above and below the formation. The packer placement or packing off technique permits an operator to test only an isolated section or cumulative sections. The testing can involve actual production into surface containers or containment of the production fluid in the closed chamber comprised by the pipe, pressure testing, physically retrieving samples of well fluids from the formation level and/or other valuable measurements.
The native pressure in producing reservoirs is controlled during drilling through the use of a carefully weighted fluid, referred to above and commonly called "drilling mud". The "mud" is continuously circulated during the drilling to remove cuttings and to control the well should a pressurized zone be encountered. The mud is usually circulated down the inside of the drill pipe and up the annulus outside of the pipe and is typically made up using water or oil based liquid. The mud density is controlled through the use of various materials for the purpose of maintaining a desired hydrostatic pressure, usually in excess of the anticipated native reservoir pressure. Polymers and such are typically added to the mud to intentionally create a "filter cake" sheath-like barrier along the wellbore surface in order to staunch loss of over-pressured drilling fluid out into the formation.
As can be easily appreciated, when an upper packer of a DST tool seals an annular area between a test string and a borehole wall, the hydrostatic pressure from the column of drilling fluid is relieved on the wellbore below the packer. The well below the packer, thus, can flow if an open fluid communication channel exists to the surface. At least the well will flow to the extent that native pressure present at the open formation of the isolated section exceeds the hydrostatic head pressure of the fluids in the drill pipe. Such produced fluids that flow to or toward the surface are either trapped in the pipe string or collected in a container of known dimensions and/or flared off. By calculating the volume of actual fluid produced, after considering such factors as the time of the test and the size of the choke used, a reasonable estimate of the ultimate potential production capacity of a well can be made. Upon occasion formation pores are too clogged, as by the drilling fluid filter cake, to be overcome by formation pressure and flow. It may be desired in such cases to deliver a gas or an acid to the formation to stimulate flow.
Many wells throughout the world contain hydrogen sulfide gas (H.sub.2 S), also known as "sour gas". Hydrogen sulfide gas can be harmful to humans or livestock at very low concentrations in the atmosphere. In Alberta, Canada, sour wells commonly produce hydrocarbon fluids with concentrations of 2-4% H.sub.2 S and often as high as 30-35% H.sub.2 S. These are among the most sour wells in the world. It is also known that sour gas can cause embrittlement of steel, such as the steel used in drill pipe. This is especially true when drill pipe contains hardened steel, which is commonly used to increase the life of the drill string. Due to a tendency for drill pipe to become embrittled when exposed to H.sub.2 S and the possibly disastrous effect of sour gas in the atmosphere with its potential for environmental damage or injury to people or animals, it is extremely uncommon to perform drill stem tests on sour wells. Even a pin hole leak in a drill pipe used for such purposes could have deleterious results.
Unfortunately, many highly productive wells are very sour and found in exploratory areas. In some cases, oil companies have been prepared to go to the expense of temporarily completing a sour well by renting production tubing and hanging it in a well without cementing casing in place, just to effect a production test. This method, due to the increase in rig time, can cost in excess of $200,000, which could be greater than the cost of a completion in shallow wells.
Coiled tubing is now known to be useful for a myriad of oilfield exploration, testing and/or production related operations. The use of coiled tubing began more than two decades ago. In the years that have followed coiled tubing has evolved to meet exacting standards of performance and to become a reliable component in the oil and gas service industry. Coiled tubing is typically manufactured from strips of low alloy mild steel with a precision cut, and rolled and seam welded in a range of OD (outside diameter) sizes, envisioned to run up to 6 inches. Currently, OD sizes are available up to approximately 4 inches. Improvements in manufacturing technology have resulted in increased material strength and consistent material quality. Development of a "strip bias weld" has improved the reliability of factory made Joints in the coiled tubing string. Heat treatment and material changes have increased resistance of the tubing to H.sub.2 S induced embrittlement and stress corrosion cracking that can incur in operations in sour environments. An increase in wall thickness and the development of higher strength alloys are also allowing the industry to increase the depth and pressure limits within which the tubing may be run. The introduction of new materials and structure, such as titanium and composite material tubing design, is also expected to further expand coiled tubing's scope of work.
Coiled tubing could be particularly valuable in sour or very sour wells due to coiled tubing's typically softer steel composition that is not so susceptible to hydrogen sulfide embrittlement. However, another factor inhibits producing sour gas or performing a DST in a sour well with coiled tubing. The repeated coiling and uncoiling of coiled tubing causes tubing walls, presently made of the steel, to plastically deform. Sooner or later the plastic deformation of the tubing wells is likely to cause a fracture. A resulting small pin hole leak or crack could produce emissions.
Oil and gas operations have known the use of concentric pipe strings. Concentric pipe strings provide two channels for fluid communication downhole, typically with one channel, such as the inner channel, used to pump fluid (liquid or gas or multiphase fluid) downhole while a second channel, such as the annular channel formed between the concentric strings, used to return fluid to the surface. (A further annulus created between the outer string and the casing or liner or wellbore could, of course, be used for further fluid communication). Which channel is used for which function can be a matter of design choice. Both concentric pipe channels could be used to pump up or down.
Concentric tubing utilizing coiled tubing, at least in part, has been proposed for use in some recent applications. Coiled tubing enjoys certain inherent advantages over jointed pipe, such as greater speed in running in and out of a well, greater flexibility for running in "live" wells and greater safety due to requiring less personnel to be present in high risk areas and the absence of joints and their inherent risk of leaks. Patterson in U.S. Pat. No. 4,744,420 teaches concentric tubing where the inner tubing member may be coiled tubing. It is inserted into an outer tubing member after that member has been lowered into the well bore. In Patterson the outer tubing member does not comprise coiled tubing. As FIG. 8 of Patterson illustrates, the inner tubing is secured within the outer tubing by spaced apart spoke-like braces or centralizers which hold the tubing members generally centered and coaxial. Sudol in U.S. Pat. No. 5,033,545 and Canadian Patent No. 1325969 discloses coaxially arranged endless inner and outer tubing strings. Sudol's coaxial composite can be stored on a truckable spool and run in or pulled out of a well by a tubing injector. Sudol's disclosure does not explicitly disclose how the coaxial tubing strings are maintained coaxial, but Sudol does show an understanding of the use of centralizers. U.S. Pat. No. 5,086,8422 to Cholet discloses an external pipe column 16 which is inserted into a main pipe column comprising a vertical section and a curved section. An internal pipe column is then lowered into the inside of the external pipe column. Cholet teaches that the pipe columns may be formed to be the rigid tubes screwed together or of continuous elements unwound from the surface. Cholet does not teach a single tubing composite that itself is wound on a spool, the composite itself comprising an inner tubing length and an outer tubing length. All of Cholet's drawings teach coaxial concentricity. U.S. Pat. No. 5,411,105 to Gray teaches drilling with coiled tubing wherein an inner tubing is attached to the reel shaft and extended through the coiled tubing to the drilling tool. Gas is supplied down the inner tube to permit underbalanced drilling. Gray, like Sudol, discloses coaxial tubing. Further, Gray does not teach a size for the inner tube or whether the inner tube comprises coiled tubing. A natural assumption would be, in Gray's operation, that the inner tube could comprise a small diameter flexible tube insertable by fluid into coiled tubing while on the spool, like wireline is presently inserted into coiled tubing while on the spool.
The present invention solves the problem of providing a safeguarded method for communicating potentially hazardous fluids and materials through coiled tubing. This safeguarded method is particularly applicable for producing and testing fluids from wells including very sour gas wells. The safeguarded method proposes the use of coiled-in-coiled tubing, comprising an inside coiled tubing length located within an outside coiled tubing length. Potentially hazardous fluid or material is communicated through the inside tubing length. The outside tubing length provides a backup protective layer. The outside tubing defines an annular region between the lengths that can be pressurized and/or monitored for a quick indication of any leak in either of the tubing lengths. Upon detection of a leak, fluid communication can be stopped, a well could be killed or shut in, or other measures could be taken before a fluid impermissibly contaminates its surroundings.
As an additional feature, the annular region between the tubing lengths can be used for circulating fluid down and flushing up the inside tubing, for providing stimulating fluid to a formation, for providing lift fluid to the inside tubing or for providing fluid to inflate packers located on an attached downhole device, etc.
The present invention also relates to the assembly of multicentric coiled-in-coiled tubing, the proposed structure offering a configuration and a method of improved or novel design. This improved or novel design provides advantages of efficient, effective assembly, longevity of use or enhanced longevity with use, and possibly enhanced structural strength.